Underground drilling, such as gas, oil, or geothermal drilling, generally involves drilling a bore through a formation deep in the earth. Such bores are formed by connecting a drill bit to long sections of pipe, referred to as “drill pipe,” so as to form an assembly commonly referred to as a “drill string.” The drill string extends from the surface to the bottom of the bore.
The drill bit is rotated so that the drill bit advances into the earth, thereby forming the bore. In a drilling technique commonly referred to as rotary drilling, the drill bit is rotated by rotating the drill string at the surface. In other words, the torque required to rotate the drill bit is generated above-ground, and is transferred to the drill bit by way of the drill string.
Alternatively, the drill bit can be rotated by a drilling motor. The drilling motor is usually mounted in the drill string proximate the drill bit. The drill bit can be rotated by the drilling motor alone, or by rotating the drill string while operating the drilling motor.
One type of drilling motor known as a “mud motor” is powered by drilling mud. Drilling mud is a fluid that is pumped under high pressure from the surface, through an internal passage in the drill string, and out through the drill bit. The drilling mud lubricates the drill bit, and flushes cuttings from the path of the drill bit. The drilling mud then flows to the surface through an annular passage formed between the drill string and the surface of the bore.
In a drill string equipped with a mud motor, the drilling mud is routed through the drilling motor. The mud motor is equipped with a rotor that generates a torque in response to the passage of the drilling mud therethrough. The rotor is coupled to the drill bit so that the torque is transferred to the drill bit, causing the drill bit to rotate.
Drilling operations can be conducted on a vertical, horizontal, or directional basis. Vertical drilling refers to drilling in which the trajectory of the drill-string is inclined approximately 10° or less in relation to the vertical. Horizontal drilling refers to drilling in which the drill-string trajectory is inclined approximately 90°. Directional drilling refers to drilling in which the trajectory of the drill-string is inclined between approximately 10° and approximately 90°.
Various systems and techniques can be used to perform directional and horizontal drilling. For example, so-called steerable systems use a drilling motor with a bent housing. A steerable system can be operated in a sliding mode in which the drill string is not rotated, and the drill bit is rotated exclusively by the drilling motor. The bent housing steers the drill bit in the desired direction as the drill string slides through the bore, thereby effectuating directional drilling. Alternatively, the steerable system can be operated in a rotating mode in which the drill string is rotated while the drilling motor is running. This technique results in a substantially straight bore.
So-called rotary steerable tools can also be used to perform directional drilling. One particular type of rotary steerable tool can include pads located on the drill string, proximate the drill bit. The pads can extend and retract with each revolution of the drill string. Alternatively, in a system that uses a non-rotating sleeve, the pads can remain fixed so that the pads exert a continuous side force. The contact the between the pads and the surface of the drill hole exerts a lateral force on the string. This force pushes or points the drill bit in the desired direction of drilling. A substantially straight bore is drilled when the pads remain in their retracted positions.
All wells typically require monitoring to determine the trajectory of the drill bit through the earth. Such monitoring typically utilizes the measurements of the bore's inclination, sometimes referred to as drift, which is the angle of the bore measured from vertical and the direction or azimuth of any such inclination measured from true north.
In addition, when drilling in “sliding mode,” i.e., while the drill string is not rotating, directional and horizontal drilling require real-time knowledge of the angular orientation of a fixed reference point on the circumference of the drill string in relation to a reference point on the bore. The reference point is typically magnetic north in a vertical well, or the high side of the bore in an inclined well. This orientation of the fixed reference point is typically referred to as “tool face,” or “tool face angle.”
Drill strings used for directional and horizontal drilling typically are equipped with a measurement while drilling (MWD) tool to provide tool face readings. The MWD tool is usually mounted in the bottom-hole assembly of the drill string. The MWD tool can include sensors for providing the measurements needed to determine tool face. An MWD tool typically includes three accelerometers mounted on orthogonal axes, whose readings may be used to determine inclination and tool face, and a triaxial magnetometer whose readings, in conjunction with those of the accelerometers, may be used to determine the azimuth heading. The MWD tool can also include a signal processor programmed to calculate tool face based on the noted measurements.
These orientation readings generated by the MWD tool need to be transmitted to the surface on a real-time basis for interpretation and analysis. Such data transmission is usually accomplished using a technique referred to as “mud-pulse telemetry.” In a typical mud-pulse telemetry system, electrical signals representing directional or other information are received and digitally encoded by a microprocessor-based encoder located in the MWD tool.
The output of the encoder can be transmitted to an electrically-powered pulser. The pulser forms part of the bottom hole assembly, and generates pressure pulses in the drilling mud in response to the output of the encoder. The pulser can generate the pulses by intermittently restricting the flow area of the drilling mud so as to back pressure the column of drilling mud located up-hole thereof.
The digitally-encoded information generated by the encoder is incorporated into the pulses. The pulses can be defined by a variety of characteristics, including amplitude (the difference between the maximum and minimum values of the pressure), duration (the time interval during which the pressure is increased), shape, and frequency (the number of pulses per unit time or, conversely, the time between pulses).
Various encoding systems have been developed using one or more pressure pulse characteristics to represent binary data, i.e., the binary digits 1 or 0. For example, a pulse of 0.5 second duration can be designated as representing the binary digit 1. A pulse of 1.0-second duration can be designated as representing the binary digit 0. Other examples can include hexadecimal encoding that uses similar techniques of pulse placement, but assigns different values to the detected positions of the generated pulses.
The pulses travel up the column of drilling mud flowing down to the drill bit, and are sensed by a pressure transducer located at or near the surface. The data from the pressure transducer is then decoded and analyzed electronically by the surface receiver, and the resulting information can be analyzed by the personnel operating the drilling rig, or other users.
Encoded data can be sent down-hole from the surface. One type of encoding system utilizes pressure by pulsing the drilling mud at or near the surface. A pressure transducer can be installed in the MWD tool to sense the pressure pulses. The encoder of the MWD tool can be programmed to decide the output signal of pressure transducer. Guidance information can thus be sent from the surface to the steering means to guide the drill bit in a desired direction. Other communication techniques can use rotation, applied weight, acoustic pulses, and electromagnetic carrier waves. These types of techniques are typically multi event and complex.
As the MWD tool and the pulser are operated on a substantially continuous basis during directional or horizontal drilling operations, a substantial amount of electrical power can be required during such operations. Electrical power can be supplied by batteries located in the down-hole assembly. In such applications, the power requirements of the MWD tool and (more so) the pulser, can drain the batteries, thereby necessitating a time-consuming removal of the drill string so that the batteries can be replaced.
Alternatively, the drill string can be equipped with a device such as a turbine-driven alternator to power the MWD tool (and the other electrical components of bottom-hole assembly).
A typical MWD tool is relatively complex and expensive. Moreover, interpretation and analysis of the directional information provided by the MWD tool is usually performed by an engineer or technician with specialized training (rather than the drill-rig operators), due to the relative complexity of these tasks.
Determining tool face on a continuous basis, in general, is not required during vertical drilling. Directional information associated with vertical drilling may be obtained as needed by performing a static survey when rotation of the drill string is interrupted to add another section of drill pipe. A static survey could be conducted, for example, by lowering a compass, a plumb line, and a camera through the drill string, and photographing the compass and plumb line when the compass and plumb line reach the bottom of the drill string.
The directional information obtained during the static survey is used to determine whether the trajectory of the bore has deviated from the vertical direction and, if so, the extent and direction of the deviation. Deviation beyond a predetermined amount, e.g., 5°, may necessitate corrective action to return the trajectory of the bore to within the limits of what is considered “vertical.”
This corrective action may necessitate removing the drill string from the bore, and configuring the drill string for directional drilling. For example, the down-hole assembly can be configured with a steerable drilling assembly comprising a mud motor or other suitable device for steering the drill bit. An MWD tool with mud-pulse telemetry equipment can also be added to the bottom-hole assembly to generate and transmit the tool-face angle data required for directional drilling. The effort required to remove and reconfigure the drill string can be substantial, and can adversely affect the schedule of drilling operations. Moreover, specially-trained engineers or technicians need to be brought on site to install the MWD tool, and to interpret and analyze the directional data from the MWD tool, which can further increase the costs and scheduling impact associated with correcting the deviation in the bore.
Static surveys may also be required by various regulatory authorities, to verify that a well remains within predetermined geographic boundaries. Static surveys acquired for this purpose must usually be overseen by a qualified surveyor located on-site as the survey is conducted. The term “qualified surveyor,” as used herein, refers to a surveyor who is qualified, certified, or otherwise approved by the governing regulatory authority to oversee the static survey.
If deviation data has been obtained during normal drilling operations, without a qualified surveyor in attendance, owners of the mineral rights and/or the regulatory authorities may require that the bottom hole location be verified and certified by a separate survey device operated by a qualified surveyor. This can involve substantial costs resulting from additional expenditures of time, and additional service fees. Therefore, the need for on-site oversight can potentially delay, and thereby increase the expense of, the drilling operation.